List of Inspection Reports 2002010

Document Sample
List of Inspection       Reports 2002010 Powered By Docstoc
					                                       December 31, 2002



Mr. John L. Skolds, President
Exelon Nuclear
Exelon Generation Company, LLC
4300 Winfield Road
Warrenville, IL 60555

SUBJECT:       BRAIDWOOD STATION, UNIT 1
               NRC SUPPLEMENTAL INSPECTION REPORT 50-456/02-10(DRP)

Dear Mr. Skolds:

On December 4, 2002, the U.S. Nuclear Regulatory Commission (NRC) completed
Supplemental Inspection Procedure 95002 “Inspection For One Degraded Cornerstone or Any
Three White Inputs In A Strategic Performance Area” at your Braidwood Station, Unit 1. The
results of this inspection were discussed on December 4, 2002, with Mr. von Suskil and
other members of your staff. The enclosed report presents the results of this inspection.

The NRC conducted this supplemental inspection as required by the NRC Action Matrix based
on our assessment of plant performance. As stated in our August 22, 2002 Mid-Cycle
Performance Review letter, plant performance at Braidwood Station Unit 1 was within the
Degraded Cornerstone Column of the NRC Action Matrix based on two White issues in the
Mitigation Systems Cornerstone.

The first issue was identified in the fourth quarter of 2001 when performance of the Unit 1
auxiliary feedwater system declined resulting in a White performance indicator (Safety
System Unavailability, Heat Removal System, Auxiliary Feedwater System) in the Mitigation
Systems Cornerstone. Two events in 2001 resulted in increased fault exposure hours for the
1B Auxiliary Feedwater pump: (1) foreign material in the control air solenoid valve for the
room cooler service water discharge isolation valve and (2) fuel shutoff solenoid valve failure.
Supplemental Inspection Procedure 95001 “Inspection For One or Two White Inputs In a
Strategic Performance Area” was conducted in February 2002 to better understand the
declining performance. The inspection results were documented in NRC Inspection Report
50-456/02-04(DRP).

The second issue pertains to your staff’s failure to take prompt corrective actions to prevent
recurring Unit 1 pressurizer power operated relief valve (PORV) air accumulator check valves
leak-through, as evidenced by repeated failures to meet testing acceptance criteria between
1991 and 2001. This resulted in several extended periods where the unit was operated in a
condition where the pressurizer PORVs may not have been able to perform their intended
safety function of opening following events which resulted in isolation of instrument air to the
containment or loss of the service air compressors. This issue was characterized as White (low
to moderate risk significance) and affected the Mitigation Systems Cornerstone.
J. Skolds                                     -2-


The supplemental inspection was an examination of activities conducted under your license as
they relate to safety and to compliance with the Commission’s rules and regulations and with
the conditions of your license. Within these areas, the inspection consisted of a selective
review of procedures and representative records and interviews with personnel. The purpose of
this inspection was to (1) provide assurance that the root and contributing causes for the White
performance indicator for the auxiliary feedwater system failures, the White inspection finding
concerning inadequate corrective actions for the Unit 1 pressurizer power operated relief valve
air accumulator check valves, and the overall performance issues which resulted in the
Degraded Cornerstone are understood; (2) independently assess the extent of condition and
generic implications; and (3) provide assurance that the corrective actions are sufficient to
prevent recurrence.

Based upon the results of this inspection, the team determined that your root cause evaluation
for the White performance indicator and the White inspection finding identified the primary and
contributory causes for the issues. Your corrective actions which included replacing the fuel
solenoid shutoff valve and revising maintenance procedures associated with the air
accumulator check valve have been completed. Therefore, the White finding associated with
the PORV air accumulator check valves will only be considered in assessing plant performance
for a total of four quarters in accordance with the guidance in IMC 0305, “Operating Reactor
Assessment Program.”

With respect to the Degraded Mitigation Systems Cornerstone, you attributed the primary root
cause to be the inability of station personnel to identify and correct long term equipment
problems and an overall tolerance for longstanding degraded material conditions. The
inspection team did not identify significant weaknesses in your evaluation. The team noted that
your proposed corrective actions and evaluation activities associated with the degraded
cornerstone were in a developmental and investigatory phase. While the team found your
approach for completing these activities to be sound, the team was not able to assess the
effectiveness or completeness of these proposed actions because these actions were
incomplete. The team also noted that the second corrective action, specifically, the
performance of aggregate system reviews, was not yet endorsed by corporate management.
Because our assessment of your corrective actions was based on your preliminary plans, we
will review and, if necessary, re-assess the effectiveness of your corrective actions during an
additional Problem Identification and Resolution inspection which will be performed in
accordance with Inspection Procedure 71152. The specific dates for this inspection will be
communicated in the end-of-cycle assessment letter.
J. Skolds                                       -3-


In accordance with 10 CFR 2.790 of the NRC’s "Rules of Practice," a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records System (PARS) component of
NRC’s document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html the Public Electronic Reading Room).

                                             Sincerely,

                                             /RA/


                                             Geoffrey E. Grant, Director
                                             Division of Reactor Projects


Docket No. 50-456
License No. NPF-72

Enclosure:     Inspection Report 50-456/02-10

cc w/encl:     Site Vice President - Braidwood
               Braidwood Station Plant Manager
               Regulatory Assurance Manager - Braidwood
               Chief Operating Officer
               Senior Vice President - Nuclear Services
               Senior Vice President - Mid-West Regional
                 Operating Group
               Vice President - Mid-West Operations Support
               Vice President - Licensing and Regulatory Affairs
               Director Licensing - Mid-West Regional
                 Operating Group
               Manager Licensing - Braidwood and Byron
               Senior Counsel, Nuclear, Mid-West Regional
                 Operating Group
               Document Control Desk - Licensing
               M. Aguilar, Assistant Attorney General
               Illinois Department of Nuclear Safety
               State Liaison Officer
               Chairman, Illinois Commerce Commission
DOCUMENT NAME: C:\ORPCheckout\FileNET\ML030020255.wpd
To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy

 OFFICE            RIII                               RIII           RIII                                               RIII
 NAME              AMStone/trn                        GGrant/SAR for
 DATE              12/31/02                           12/31/02
                                                      OFFICIAL RECORD COPY
J. Skolds               -4-


ADAMS Distribution:
AJM
DFT
MLC
RidsNrrDipmIipb
GEG
HBC
SPR
C. Ariano (hard copy)
DRPIII
DRSIII
PLB1
JRK1
            U.S. NUCLEAR REGULATORY COMMISSION

                          REGION III


Docket No:           50-456


License No:          NPF-72


Report No:           50-456/02-10(DRP)


Licensee:            Exelon Generating Company, LLC


Facility:            Braidwood Station, Unit 1


Location:            35100 S. Route 53
                     Suite 84
                     Braceville, IL 60407-9617


Dates:               November 4 through December 4, 2002


Inspectors:          S. Burton, Senior Resident Inspector
                     R. Lerch, Project Engineer
                     N. Shah, Resident Inspector


Approved by:         Ann Marie Stone, Chief
                     Branch 3
                     Division of Reactor Projects
                                    SUMMARY OF FINDINGS


IR 05000456-02-10; Exelon Generating Company, LLC; on 11/4-12/4/2002, Braidwood Station;
Unit 1. Supplemental Inspection - Mitigation Systems Cornerstone.

Cornerstone: Mitigation Systems

The U.S. Nuclear Regulatory Commission (NRC) performed this supplemental inspection to
assess, both individually and collectively, the licensee’s root cause evaluations and corrective
actions associated with a degraded Mitigation Systems Cornerstone which resulted from a
White performance indicator for the auxiliary feedwater system (AFW) safety system
unavailability and a White finding pertaining to inadequate corrective actions for pressurizer
power operated relief valves (PORV) air accumulator check valves. Supplemental Inspection
Report 50-456/02-04 documented the details and the initial review of the White AFW safety
system unavailability performance indicator. The inadequate corrective actions associated with
the PORV air accumulator check valves was previously characterized as White in the NRC’s
final significance determination letter dated July 12, 2002, and was defined as having low to
moderate risk significance. Inspection Report 50-456/02-03; 50-457/02-03 documented the
details and the initial review of that finding.

During this supplemental inspection, performed in accordance with Inspection Procedure
95002, the team evaluated the issues both individually and collectively. The team determined
that the licensee performed a comprehensive evaluation of the issues individually and
collectively. The licensee attributed the primary root cause for the degraded cornerstone to be
the inability of station personnel to identify and correct long term equipment problems and an
overall tolerance for longstanding degraded material conditions. The licensee’s planned
corrective actions included a periodic review of mitigation system performance and a human
performance improvement program.

The team did not identify any significant findings during their review of the licensee’s evaluation.
The team concluded that the primary root cause, the inability of station personnel to identify and
correct long term equipment problems and an overall tolerance for longstanding degraded
material conditions, represented a human performance cross cutting issue. The team identified
that the proposed corrective actions for the contributing causes were in a developmental and
investigatory phase. The team found the approach for completing these activities to be sound,
but were unable to assess the effectiveness or completeness of these proposed actions.
Because the team could not confirm that the proposed actions will be initiated, the licensee’s
corrective actions associated with the degraded cornerstone will be re-assessed during a
subsequent Problem Identification and Resolution inspection.

Given the licensee’s acceptable performance in addressing the PORV air accumulator check
valves, the White finding associated with this issue will only be considered in assessing plant
performance for a total of four quarters in accordance with the guidance in IMC 0305,
“Operating Reactor Assessment Program.”




                                                 2
                            SUMMARY OF FINDINGS (cont’d)


A.   Inspector-Identified Findings

     No findings of significance were identified.

B.   Licensee-Identified Findings

     No findings of significance were identified.




                                              3
                                      REPORT DETAILS


01     INSPECTION SCOPE

The U.S. Nuclear Regulatory Commission (NRC) performed this supplemental inspection to
assess, both individually and collectively, the licensee’s root cause evaluations and corrective
actions associated with a degraded Mitigation Systems Cornerstone which resulted from a
White performance indicator for auxiliary feedwater system (AFW) unavailability and a White
finding pertaining to inadequate corrective actions for power operated relief valves (PORV) air
accumulator check valves. The White AFW safety system unavailability performance indicator
was documented in Supplemental Inspection Report 50-456/02-04. The inadequate corrective
actions associated with the PORV air accumulator check valves was previously characterized
as White in the NRC’s final significance determination letter dated July 12, 2002.

02     EVALUATION OF INSPECTION REQUIREMENTS

02.01 Problem Identification

.1     Concerns with the Unit 1B Diesel Driven Auxiliary Feedwater Pump

 a.    Determination of who (i.e., licensee, self revealing, or NRC) identified the issue and
       under what conditions

       In Supplemental Inspection Report 50-456/02-04, the NRC documented that the
       conditions leading to the White performance indicator for the AFW system were
       self-revealing. In the fourth quarter of 2001, the accumulated unavailability/fault
       exposure time for the 1B AFW pump exceeded the NRC performance indicator White
       threshold. This resulted from the pumps failing to start during surveillance testing
       between September 1999 and November 2001, and from the failure of the pump cooling
       water outlet valve to open in April 2001.

       The primary contributor to these events was the failure of the 1B AFW pump fuel shutoff
       solenoid valve. Following the pump’s failure to start in November 2001, the licensee
       identified that this valve was inappropriate for the pump’s fuel control system. The valve
       was designed for use in a hydraulic oil versus lubricating oil applications. Therefore, the
       internal clearances of the valve were smaller and were not designed for the higher
       particle counts in the pump lubricating oil. The licensee also identified that the
       1B AFW pump’s particle count was within limits, but was significantly higher than the
       2B AFW pump. This accounted for the increased number of failures on the
       1B AFW pump.

       The team identified no additional issues during their review.




                                                4
 b.   Determine of how long the issue existed, and prior opportunities for identification

      In Supplemental Inspection Report 50-456/02-04, the NRC identified that the licensee
      had taken inadequate action to identify and correct the problem with the fuel shutoff
      solenoid valve.

      The team identified no additional issues during their review.

      Between 1992 and 1999, the 1B AFW pump was slow to start on five occasions. The
      licensee failed to initiate actions to identify the cause for each event. The licensee
      removed individual pump components and analyzed them for failure after a slow start in
      September 1999. However, the licensee took no further actions to determine the root
      cause when problems with the individual components were not identified. After the
      November 2001 failure resulted in the performance indicator exceeding the White
      threshold, the licensee determined that the installed fuel shutoff solenoid valve was
      inappropriate for the pump fuel control system.

 c.   Determination of the plant specific risk consequences (as applicable) and compliance
      concerns associated with the issue

      The licensee’s risk evaluation was reviewed and documented in Supplemental
      Inspection Report 50-456/02-04 and no problems were identified. A Non-Cited Violation
      and Green finding for the licensee’ failure to identify the cause and prevent recurrence
      of the AFW pump problems was documented in that report.

      The team identified no additional issues during their review.

.2    Unit 1 Pressurizer Power Operated Relief Valve Air Accumulator Check Valve Failures

 a.   Determination of who (i.e., licensee, self revealing, or NRC) identified the issue and
      under what conditions

      The failure of the pressurizer PORV air accumulator check valves was NRC-identified
      and documented in Inspection Reports 50-456/95010; 50-457/95010, 50-456/02-03;
      50-457/02-03, and 50-456/02-07; 50-457/02-07. The PORV air accumulator check
      valves were designed to maintain an accumulator pressurized with operating air in the
      event that the normal supply of air was lost. Between 1991 and 2001, multiple failures
      had occurred which resulted in extended periods with the PORV air accumulator check
      valves potentially unable to perform their intended safety function. In many cases, past
      failures were not documented in a condition report (CR) or were documented without
      identifying the cause of the failures. Licensee Event Reports (LERs)
      50-456/2002-002-00 and -01 discussed this issue. The licensee initiated CR 95245 to
      determine the root cause of the failures.

 b.   Determination of how long the issue existed, and prior opportunities for identification

      In 2002, the NRC identified that since 1991, the licensee had multiple PORV check
      valve failures, but failed to take the appropriate actions. Examples included:


                                               5
      •      In 1992, all four check valves failed during surveillance testing. Although the
             licensee performed an evaluation, the evaluation was closed without identifying
             the cause of the failures.

      •      In 1994, two of the four check valves failed during surveillance testing. The
             licensee did not initiate a condition report for the failures and did not identify the
             cause for the failures.

      •      In January 1995, the “A” train check valves failed their surveillance tests and a
             condition report was initiated; however, the condition report was closed with no
             action taken and again, the licensee did not identify the cause for the failures.

      •      As documented in Inspection Reports 50-456/95010; 50-457/95010, the NRC
             noted that the licensee had not taken appropriate action to address the recurrent
             valve failures.

      •      In the fall of 1995, all four check valves failed during surveillance testing, but
             again, the licensee did not initiate a condition report to document the failures and
             again, did not identify the cause for the failures.

      •      In 1997, all four check valves initially failed during surveillance testing and an
             action item was initiated to identify the cause of the failures. However, this item
             was closed in 1998 without being completed.

      •      In 2001, all four check valves failed during surveillance testing and a condition
             report was initiated. This report concluded that the failures were maintenance
             preventable functional failures requiring an apparent cause evaluation (ACE).
             However, this evaluation did not identify the root cause for the failures (incorrect
             disc to valve seat clearance) and concluded that the valves were operable.

 c.   Determination of the plant specific risk consequences (as applicable) and compliance
      concerns associated with the issue

      The NRC’s risk assessment concluded that the PORV air accumulator check valve
      repeated failures was of low to moderate safety significance, a White finding. The
      licensee’s risk assessment agreed with the NRC’s assessment. The NRC concluded
      that the failures were a violation of 10 CFR Part 50, Appendix B, Criterion XVI,
      “Corrective Action,” for the failure to properly identify the reason for the failures and to
      take appropriate corrective action. In letters dated June 25 and July 23, 2002, the NRC
      summarized the results of the risk evaluation and transmitted the Notice of Violation.
      On August 22, 2002, the licensee transmitted the response to the Notice of Violation,
      including the identified root cause and the associated corrective actions.

.3    Inability to Identify and Correct Longstanding Equipment Problems Leading to Degraded
      Cornerstone

 a.   Determination of who (i.e., licensee, self revealing, or NRC) identified the issue and
      under what conditions


                                                6
     In a letter dated July 23, 2002, the NRC stated that the combination of the White
     performance indicator for the 1B AFW pump and the White finding for the PORV air
     accumulator check valves resulted in a degraded Mitigation Systems Cornerstone under
     the Revised Reactor Oversight Process. This conclusion was restated by the NRC in an
     August 22, 2002 letter summarizing Braidwood’s Mid-Cycle Performance Review. In
     response, the licensee initiated CR 113947 to perform a root cause evaluation to identify
     the issues leading to the degraded cornerstone.

     The licensee concluded that the degraded cornerstone was caused by an inability to
     identify and correct longstanding equipment problems and an overall tolerance for
     longstanding degraded material conditions. This was exemplified by the multiple missed
     opportunities to identify and correct the problems associated with the 1B AFW pump
     (Section 02.01.1.a) and the PORV air accumulator check valves (Section 02.01.2.a).
     The team noted that this conclusion was also consistent with licensee self-assessments
     of equipment reliability monitoring conducted in August and September 2002.

b.   Determination of how long the issue existed, and prior opportunities for identification

     The licensee’s root cause evaluation documented the dates of the issues and the
     missed opportunities for identification. The degraded Mitigation Systems Cornerstone
     resulted from the failure to identify and correct recurring problems with the 1B AFW
     pump and PORV air accumulator check valves (Sections 02.01.1.b and 02.01.2.b). The
     licensee concluded that the issues would have been resolved through the station’s
     existing equipment reliability programs had opportunities for identification been
     recognized and appropriate actions been taken.

     The team independently reviewed the station’s existing equipment reliability programs,
     specifically, the licensee’s system health indicator program (SHIP) and rework
     monitoring programs, to assess their effectiveness. The SHIP was chosen because it
     provided an overall indicator of system health by integrating the results of other
     equipment monitoring processes, such as the maintenance rule and condition reporting
     programs. The rework program was chosen because of the recurring failure to correctly
     perform maintenance on both the 1B AFW pump fuel solenoid valve and the PORV air
     accumulator check valves.

     The team concluded that the SHIP adequately monitored equipment performance and
     integrated the results from other equipment monitoring programs. However, the team
     noted that these programs relied heavily on the corrective action program for capturing
     equipment performance issues. The failure to write or fully evaluate condition reports
     for the AFW pump and the PORV air accumulator check valve problems contributed to
     the lack of assessment in the SHIP and maintenance rule programs (Sections 02.01.1.b
     and 02.01.2.b).

     The team concluded that the rework program did not adequately monitor rework issues
     because the design of the program allowed some equipment performance trends to be
     unidentified. For example, the licensee identified that the rework identification process
     was limited to a one year scope. The PORV air accumulator check valve failures
     occurred during an 18-month routine surveillance; therefore, would not be classified as
     rework. The licensee planned to re-assess the definition of rework. Additional

                                              7
      examples of programmatic design impediments identified by the team are discussed in
      Section 02.04.

 c.   Determination of the plant specific risk consequences (as applicable) and compliance
      concerns associated with the issue

      The team performed a qualitative risk assessment of the licensee’s overall findings and
      identified no significant issues. The licensee’s risk evaluation for the 1B AFW pump and
      PORV check valve failures are discussed in Supplemental Inspection Report
      50-456/02-04 and Section 02.01.2.c of this report, respectively. The licensee also
      identified several longstanding issues with other mitigating systems during the
      evaluation of the degraded cornerstone. These issues were entered into their corrective
      action program for resolution.

      The team performed an independent review of the Unit 1 and Unit 2 125v DC battery
      systems to evaluate the accuracy of the licensee’s conclusions for the degraded
      cornerstone root cause. The team reviewed selected condition reports, work packages,
      modifications, and other relevant documentation generated since 1999 and determined
      that equipment issues were being appropriately handled. No new issues were identified.

02.02 Root Cause and Extent of Condition Evaluation

.1    Programmatic Concerns with the Unit 1B Diesel Driven Auxiliary Feedwater Pump

 a.   Evaluation of methods used to identify root causes and contributing causes

      The methods used to identify the root and contributing causes were discussed in
      Supplemental Inspection Report 50-456/02-04. The licensee used several different
      analysis techniques including Event and Causal Factor charting, Barrier Analysis,
      Failure Modes and Effects Analysis, Change Analysis, and Tap Root methodology. The
      team concluded that the licensee used a formal, structured approach to perform the
      common cause analysis to identify root causes and contributing factors. No new issues
      were identified.

 b.   Level of detail of the root cause evaluation

      Supplemental Inspection Report 50-456/02-04 documented that the level of detail of the
      root cause evaluation for exceeding the performance indicator threshold was adequate.
      However, the level of detail of previous ACE determinations was poor. The lack of ACE
      quality involving the PORVs was later identified by the licensee as a causal factor for the
      degraded cornerstone.

 c.   Consideration of prior occurrences of the problem and knowledge of prior operating
      experience

      Supplemental Inspection Report 50-456/02-04 documented that the licensee’s review of
      previous operating history of both Braidwood and Byron operating units was adequate.
      The team did not identify any new issues during their review.


                                               8
 d.   Consideration of potential common cause(s) and extent of condition of the problem

      Supplemental Inspection Report 50-456/02-04 documented that the licensee
      appropriately identified the potential for a common cause failure mode based on the
      inappropriate application of the diesel fuel shutoff solenoid valve. The team did not
      identify any new issues during their review.

.2    Unit 1 Pressurizer Power Operated Relief Valve Air Accumulator Check Valve Failures

 a.   Evaluation of methods used to identify root causes and contributing causes

      The team reviewed root cause evaluation CR 95245 for the PORV air accumulator
      check valve failures and concluded that the Failure Modes and Effects Analysis
      technique was appropriately used by the licensee and adequately identified the root
      causes. The licensee attributed the check valve failures to improper valve assembly
      following planned maintenance. Specifically, the valve was reassembled with an
      incorrect disc to valve seat clearance. This prevented the valve disc from fully engaging
      with the seat and caused the valve o-ring to become dislodged following
      post-maintenance testing. The improper maintenance was caused by not using existing
      vendor guidance for performing work on these check valves. The licensee could not
      identify why the incorrect guidance was used for the Unit 1 valves. The licensee
      performed a review of past work packages for Unit 2 and confirmed that the tolerances
      had been checked, which indicated the condition did not exist on Unit 2.

      The team noted that the licensee originally intended to investigate the equipment
      problems and possible programmatic and institutional issues. However, during their
      evaluation, the licensee determined that the programmatic review was not conducted.
      As stated above, the licensee concluded that this lack of quality in the ACE was a causal
      factor for the degraded cornerstone.

 b.   Level of detail of the root cause evaluation

      The level of detail was adequate for the technical issues addressed and appeared to
      resolve the functional failure of the check valves.

 c.   Consideration of prior occurrences of the problem and knowledge of prior operating
      experience

      The licensee’s review of prior occurrences and operating experience was adequate. All
      identified issues and failures of the PORV air accumulator check valves from 1992 to
      date were reviewed by the licensee. A review of industry experiences was also
      included.

 d.   Consideration of potential common cause(s) and extent of condition of the problem

      The root cause assessment of common causes and extent of condition was adequate.
      The licensee’s extent of condition review considered all Anderson Greenwood valves
      and concluded that the maintenance procedures for these valves had been previously
      updated. The improper maintenance issues only applied to the Unit 1 PORV air

                                               9
      accumulator check valves. The licensee also contacted station personnel at the Byron
      Station, Units 1 and 2 to verify accuracy of their maintenance procedures. No concerns
      were identified.

.3    Inability to Identify and Correct Longstanding Equipment Problems Leading to Degraded
      Cornerstone

 a.   Evaluation of methods used to identify root causes and contributing causes

      Overall, the licensee used appropriate methods to identify the root causes and causal
      factors. The team reviewed root cause report CR 113947 and interviewed members of
      the root cause analysis team. The licensee started the root cause analysis with the
      Event and Causal Factor charting method to describe the time lines for the two issues
      involved: the 1B AFW failed starts and the PORV air accumulator check valve failures.
      Seventeen causal factors were identified. A barrier analysis was then performed to
      identify equipment or program failures common to the two issues. The licensee also
      used the Tap Root methodology to further identify causes due to human error,
      programmatic, or organizational failure modes.

      The licensee concluded that the inability of the station personnel to identify and correct
      long term equipment problems was the root cause for the degraded cornerstone. The
      licensee identified numerous causal factors related to poor implementation of the
      corrective action program and other programs by various organizations. Additionally,
      the licensee concluded that prior correction of these causal factors could have
      prevented or significantly mitigated the degraded cornerstone. For example:

      •      A 1995 issue on PORV check valve failures was closed in 1998 without
             adequate review for additional corrective actions (Causal Factor 10).

      •      An engineering request to replace the check valves was inappropriately canceled
             in 1997 without resolving the issue (Causal Factor 6).

      •      The nuclear tracking system records indicate that the PORV check valves may
             have failed a test in the spring of 1997, but documentation was lacking. No
             condition report was written (Causal Factor 9).

      •      The maintenance rule reviews did not include work history as specified in the
             reliability criteria and failed to identify the functional failure of the PORV check
             valves (Causal Factor 7).

      •      Two PORV check valves failed in 2000; however, station personnel did not write
             condition reports (Causal Factor 9).

      •      A condition report written for the PORV check valve failures in the fall of 2001
             was not adequately evaluated. The apparent cause evaluation failed to identify
             the implications of the failures. (Causal Factors 11, 12, 15 and 16).

      In their evaluation, the licensee classified these issues under “Human Performance
      Difficulty” and concluded that these represented widespread human performance

                                               10
      deficiencies which resulted in the inability of the station personnel to correct and identify
      long term equipment problems. The team concluded that these issues represented a
      human performance cross cutting issue (Section 4OA4).

 b.   Level of detail of the root cause evaluation

      The level of detail in the root cause report, CR 113947, provided sufficient information to
      support the conclusions reached. Included in the report was a discussion of the
      licensee’s methodology and scope, a time line and description of events, an extent of
      condition assessment, the safety significance evaluation, and data and analysis for
      internal and external operating experiences. Additional detail was documented in the
      results of the review efforts conducted by the five teams established for the root cause
      evaluation.

 c.   Consideration of prior occurrences of the problem and knowledge of prior operating
      experience

      The root cause evaluation, in building on the contributing issue root causes, adequately
      captured the equipment issues, prior occurrences, and operating experiences. The
      issues with the auxiliary feed pump and the PORVs had been determined to be long
      term and repetitive. All of the occurrences and prior experiences were therefore
      factored into this root cause analysis through the event and causal factor charting.

 d.   Consideration of potential common cause(s) and extent of condition of the problem

      The licensee performed extensive reviews of all mitigating systems to identify
      outstanding or existing component problems. This included system walkdowns and an
      aggregate review of condition reports, work requests, and other management inputs to
      system status, such as maintenance rule, system health and component health reviews.
      The licensee did not identify any operability issues; however, some potential equipment
      concerns were identified. No immediate actions were required. The team did not
      identify deficiencies with the licensee’s evaluation or any additional equipment concerns.

      The team noted that although human performance was identified as a root cause, the
      licensee did not specifically conduct an extent of condition review on human
      performance. This is further discussed in Section 02.04.

02.03 Corrective Actions

.1    Programmatic Concerns with the Unit 1B Diesel Driven Auxiliary Feedwater Pump

 a.   Appropriateness of corrective action(s)

      Corrective actions to prevent recurrence generated as a result of the licensee root
      cause evaluation were reviewed and documented in Supplemental Inspection Report
      50-456/02-04. The team assessed the appropriateness of several corrective actions for
      contributing causes which were completed subsequent to the inspections performed for
      Inspection Report 50-456/02-04. Corrective actions reviewed included action tracking
      item (ATI) 84527-22, which reviewed the parts evaluation methodology; ATI 84527-25,

                                                11
      which provided training on the event; and ATI 84527-27, which reviewed the
      procurement process that allowed the purchase of a valve designed for hydraulic fluid
      versus oil applications. The corrective actions reviewed appeared appropriately closed
      and adequate to prevent recurrence.

 b.   Prioritization of corrective actions

      The prioritization of the corrective actions for the root cause evaluation was evaluated
      and found acceptable as documented in Supplemental Inspection Report 50-456/02-04.
      The team did not identify any new issues during their review of related action tracking
      items.

 c.   Establishment of schedule for implementing and completing the corrective actions

      The licensee’s schedule for implementing and completing the corrective actions was
      determined to be acceptable as documented in Supplemental Inspection Report
      50-456/02-04. The team did not identify any new issues during their review of the
      related action tracking items.

 d.   Establishment of quantitative or qualitative measures of success for determining the
      effectiveness of the corrective actions to prevent recurrence

      The measures of success for determining the effectiveness of the corrective actions
      generated as a result of the licensee root cause evaluation were reviewed and
      documented in Supplemental Inspection Report 50-456/02-04. The team did not identify
      any new issues during their review of related action tracking items.

.2    Unit 1 Pressurizer Power Operated Relief Valve Air Accumulator Check Valve Failures

 a.   Appropriateness of corrective action(s)

      The licensee’s review for corrective actions and the extent of conditions for the PORV
      air accumulator check valve failures appeared to be adequate. The team reviewed the
      corrective actions to prevent recurrence and extent of condition analysis for
      LER 50-456/02-02-00, “Failure of Pressurizer PORV Instrument Air Accumulator
      Isolation Check Valves Caused by Improper Maintenance Activities,” and the associated
      White finding.

      The licensee identified three corrective actions to prevent recurrence (CAPR) and
      multiple actions to address contributing causes associated with this issue. Corrective
      actions included reviewing and revising the applicable maintenance and surveillance
      procedures. The licensee also planned to replace the check valves during the next
      refueling outage. The team verified that corrective actions and extent of condition
      review were entered and tracked in the licensee’s corrective program.

 b.   Prioritization of corrective actions

      Prioritization of the corrective actions generated from the root cause evaluation
      appeared to be adequate and commensurate with their regulatory and safety

                                                12
      significance. The prioritization of corrective actions was completed as required by
      Procedure LS-AA-125, “Corrective Action Program (CAP) Procedure,” and
      Procedure LS-AA-125-1006, “CAP Process Expectations Manual.”

      The team determined that the licensee’s process did not include probabilistic risk
      assessments as a quantitative method to assist with prioritization of corrective actions.
      Procedures LS-AA-125 and LS-AA-125-1006 utilized a qualitative evaluation of risk and
      uncertainty. Risk was defined as an assessment of consequences, as identified in a list
      of examples for determining significance level, and the probability of recurrence if left
      uncorrected. Uncertainty was defined as an assessment of the lack of understanding of
      the issue, combined with an assessment of the potential lack of effectiveness
      considering the proposed corrective actions. A matrix comparing the risk and
      uncertainty determinations was then used to determine the final guidance for which type
      of evaluation to perform. The procedure then recommended a completion time for each
      type of causal evaluation. Actions or work assignments resulting from the causal
      evaluation were assigned due dates, which were mutually agreed upon between
      process management and the assignee, with the primary focus being on management’s
      perception of importance and workload. No procedural guidance existed for
      establishing or prioritizing action due dates. Although no inappropriately prioritized
      actions were identified, the team concluded that the lack of a probabilistic tool as a
      prioritization aid could allow some subtle higher risk activities to be prioritized incorrectly.

 c.   Establishment of schedule for implementing and completing the corrective actions

      The due dates established for implementing the corrective actions appeared sufficient to
      prevent recurrence of a similar event. The schedule for implementing corrective actions
      existed as assigned due dates within the corrective action program tracking system.
      The selection of due dates was made using the process described in Section 02.03.2.b.
      Corrective actions specific to the facility appeared reasonable and were scheduled for
      completion prior to the end of the next refueling outage.

 d.   Establishment of quantitative or qualitative measures of success for determining the
      effectiveness of the corrective actions to prevent recurrence

      The licensee planned to conduct an effectiveness review of the corrective actions in
      December 2003. No other formal measures of success had been established. An
      extended discussion of this observation is included in Section 02.03.3.d.

.3    Inability to Identify and Correct Longstanding Equipment Problems Leading to Degraded
      Cornerstone

 a.   Appropriateness of corrective action(s)

      The proposed corrective actions and the interim measures for the degraded Mitigation
      Systems Cornerstone appeared to be adequate and were appropriate for the root cause
      identified. Corrective actions were established as a product of the root cause
      methodology utilized by the licensee and scheduled as described in Section 02.03.2.b.



                                                13
     The team verified that the proposed corrective actions addressed the root causes and
     each of the causal factors. Corrective actions were entered into the licensee’s
     corrective action program in accordance with Procedure LS-AA-125 as CR 00113947.

     The licensee identified two corrective actions to prevent recurrence for the degraded
     cornerstone root cause assessment. The first CAPR (CAPR1) required development of
     an awareness improvement plan to modify behavior relative to human performance
     issues identified during the root cause assessment. The second CAPR (CAPR2) was
     the development of a process to perform a recurring review of safety significant systems
     that would assess the effectiveness of interfacing processes such as maintenance rule,
     SHIP, and corrective actions. Both CAPRs were in the developmental phase with a
     December 31, 2002, due date for release of the approved formal plan/program.

     For each CAPR, the team reviewed the licensee’s proposed formal plans and
     methodologies and determined that the process appeared adequate for addressing the
     identified root causes if implemented as proposed at the time of the inspection.

     For CAPR1, several interim actions had been accomplished or were in progress at the
     time of the inspection. These included general awareness meetings with senior station
     management, information distributed in site communications documents, first line
     supervisory meetings, recovery bulletins, and team reviews of the issues. Topics
     contained within these measures included discussions on causal factors, management
     expectations, and status of station progress in addressing the causal factors. The
     licensee planned additional actions such as future team reviews, meetings, and
     measures for success.

     For CAPR2, the licensee planned to perform a vertical review of mitigating systems with
     respect to interfacing programs, such as maintenance rule or SHIP. This methodology
     which was used during the root cause evaluation appeared adequate as a format for the
     corrective action. The team noted that the licensee indicated that corporate
     management had yet to fully endorse CAPR2 and planned a trial period prior to site or
     fleet implementation of the process.

     Because the team could not confirm that the proposed actions associated with the
     CAPRs will be initiated, the licensee’s corrective actions associated with the degraded
     cornerstone will be re-assessed during a subsequent Problem Identification and
     Resolution inspection.

b.   Prioritization of corrective actions

     Prioritization of the corrective actions from the root cause evaluation appeared to be
     adequate and commensurate with their regulatory and safety significance. Interim
     measures established for CAPR1 were commensurate with the safety significance of the
     identified root cause and appeared to be adequate until a formal plan for improving
     human performance could be established. Prioritization of corrective actions was
     completed using the process described in Section 02.03.2.b.




                                            14
c.   Establishment of schedule for implementing and completing the corrective actions

     The licensee’s established due dates for implementing corrective actions appeared
     sufficient to prevent recurrence of a similar event. The schedule for implementing
     corrective actions existed as assigned due dates within the corrective action program
     tracking system. The selection of due dates was made using the process described in
     Section 02.03.2.b.

     The team noted that many of the corrective actions were investigative in nature, or
     covered potentially generic issues. For example, ATI 113947-16 required an extent of
     condition review of engineering requests that may have been inappropriately canceled,
     ATI 113947-22 required a focused area self-assessment of the check valve program to
     evaluate the current condition and compliance with corporate procedures, and
     ATI 113947-40 required an evaluation of engineering program trending/concerns to
     ensure compliance with procedures. Additional actions may result if discrepancies are
     identified during these reviews.

     The team reviewed the procedures for establishing, tracking, and closing action items.
     The procedures appeared adequate; however, the team noted that the procedure did
     not require action items which were closed to another action item to be cross-referenced
     which could result in inappropriate closure of items. For example, the licensee initiated
     engineering request 9601111 to replace PORV air accumulator check valve seats with
     more appropriately designed seats. This request was placed on hold pending the
     outcome of corrective action E20-1/2-96-225 which was later canceled. No further
     action was performed. The licensee concluded that ER 9601111 was inappropriately
     closed. The licensee identified several additional examples including:

     •      A condition report initiated on May 15, 2001, documenting the auxiliary feedwater
            unavailability was closed to an apparent cause investigation which was in
            progress.

     •      Condition Report 456-201-95-0180 documenting a problem with maintaining
            PORV air system pressure was closed to a work order with no action taken.

     •      A 1992 condition report, CDE 20-1-92-227, to investigate PORV air accumulator
            check valve failures was closed to a work request.

     Without cross-referencing, it was not clear to the team how inappropriate closure of
     items would be prevented. The team noted that at the end of the inspection, the
     licensee initiated actions to evaluate this cross-referencing concern.

d.   Establishment of quantitative or qualitative measures of success for determining the
     effectiveness of the corrective actions to prevent recurrence

     The team did not assess the licensee’s measures of success because the CAPRs
     remained in a developmental phase. The team noted that the licensee planned to
     perform an effectiveness review in December 2003. Procedure LS-AA-125 stated that
     “effectiveness reviews should normally be performed after implementation of the final
     CAPR and sufficient time has elapsed to challenge the CAPR(s).” The team observed

                                            15
      that all effectiveness reviews were scheduled well after CAPRs were scheduled for
      completion and that no in-progress effectiveness reviews were planned.

      The team observed that the licensee’s use of effectiveness reviews was a lagging
      indicator of success, only occurring after the potential for failure had passed. Through
      interviews, the team determined that the licensee had not considered any in-progress or
      leading indicators of effectiveness. However, several informal tools for measuring
      improvements in human performance such as SHIP, corrective and elective
      maintenance work order back log, configuration control event monitoring, productivity
      assessments, and degraded cornerstone action item completion status were utilized.

      Although the licensee’s corrective actions to prevent recurrence were not formalized at
      the time of this inspection, the team found the licensee’s approach for completing these
      activities to be sound. The team was unable to assess the effectiveness or
      completeness of these proposed actions; however, noted that the licensee had informal
      tools for monitoring in-progress performance. The effectiveness of the corrective
      actions will be evaluated during a subsequent Problem Identification and Resolution
      Inspection in accordance with the Reactor Oversight Program.

02.04 Independent Assessment of Extent of Condition and Generic Implications

      The team performed an independent extent of condition assessment and did not identify
      any significant issues. The team concluded that correction of the root cause, the
      inability of the station to identify and correct long standing equipment problems and an
      overall tolerance for longstanding degraded material conditions, should address any
      generic implications associated with implementation of the various equipment monitoring
      programs.

      The team noted that although human performance was identified as a root cause, the
      licensee did not specifically conduct an extent of condition review on human
      performance. The team identified that additional human performance concerns in the
      area of configuration control and barrier impairments had been recently identified by the
      licensee but were not incorporated into the licensee’s review for the degraded
      cornerstone. Further review into other area such as emergency preparedness, fire
      protection and inservice testing and inspection may be warranted to ensure appropriate
      scope to the human performance issue.

      The team also identified that the design of several related programs may provide the
      potential for issues to go unrecognized, become delayed, or closed without the
      generation of a condition report as identified below:

      •      The team observed that a condition report was not initiated to document a black,
             gummy residue found inside the 1B AFW pump lube oil cooler service water inlet
             valve. Troubleshooting was performed under Work Request 99201097-01,
             dated September 2001. The licensee indicated that a condition report was not
             written because the residue affected the valve’s ability to close but did not affect
             the valve’s safety-related function to open. However, the team observed that by
             not writing a condition report the licensee could not evaluate some fundamental
             questions such as: Where did the residue originate, was the residue present in

                                              16
             other service water systems, did the valve failure to close indicate a need to
             increase the frequency to clean and inspect the valve, and was the amount of
             the residue changing with time or season? The licensee entered this
             observation into their corrective action program as CR 133091.

      •      Step C14, of station procedure BwHS TRM 3.8.c, “125 Volt ESF [Engineered
             Safety Feature] Battery Bank and Rack Surveillance,” allowed observations of
             lead-sulfate crystals identified during DC battery inspections to be closed to an
             action request instead of a condition report. Because operability evaluations are
             part of the condition reporting process, lead-sulfate crystals may not be properly
             evaluated by closure to an action request. The licensee initiated CR 133412 to
             address the DC battery procedural concern.

      •      Subjectivity in the rework process may not provide for proper evaluation of trends
             or extent of condition. Maintenance that did not involve disassembly of the
             affected component was not considered rework by the mechanical maintenance
             department, whereas the definition was different for the instrument maintenance
             department. For example, when comparing the equivalent task of sending a
             technician to re-torque a nut or reset a potentiometer, re-torqueing of a nut was
             not rework, but resetting a potentiometer was rework. The team concluded that
             this practice may provide the potential for trends such as inadequate training or
             procedures to go unidentified. The licensee initiated CR 131318 to evaluate the
             rework process.

4OA4 Cross-Cutting Findings

      The team observed that the licensee attributed the cause for the degraded cornerstone
      to human performance deficiencies, resulting in the inability of the station to identify and
      correct long term equipment problems. The team concluded that this represented a
      human performance cross-cutting issue. This issue resulted in a degraded cornerstone
      for mitigation systems (Section 02.02.3.a).

03    MANAGEMENT MEETINGS

      Exit Meeting Summary

      The team presented the inspection results to Mr. von Suskil and other members of
      licensee management at the conclusion of the inspection on December 4, 2002. The
      licensee acknowledged the findings presented. No proprietary information was
      identified.




                                               17
                                KEY POINTS OF CONTACT

Licensee
J. von Suskil, Site Vice President
T. Joyce, Plant Manager
K. Ainger, Licensing Manager
J. Bailey, Regulatory Assurance - USNRC Coordinator
R. Blaine, Radiation Protection Manager
S. Butler, Regulatory Assurance Corrective Action Program Administrator
G. Dudek, Operations Manager
C. Dunn, Site Engineering Director
A. Ferko, Regulatory Assurance Manager
G. Heisterman, Maintenance Manager
R. Himes, Program Engineer Manager
K. Jury, Licensing Director, Exelon
F. Lentine, Design Engineer Manager
D. Meyers, Training Director
D. Riedinger, Electrical Design Engineering Support
L. Rhoden, On-Line Work Control Manager
M. Smith, Plant Engineering Manager

U. S. Nuclear Regulatory Commission
M. Chawla, Project Manager, Office of Nuclear Reactor Regulation
G. Grant, Director, Division of Reactor Safety
A. Stone, Chief, Reactor Projects Branch 3


                  LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

 Opened
 None


 Closed
 None


 Discussed
 None




                                             18
                     LIST OF DOCUMENTS REVIEWED

BwAR 1-21-D6; 125V DC Bus 111 Ground; Revision 7

BwAR 1-22-D6; 125V DC Bus 112 Ground; Revision 7

BwAR 2-21-D6; 125V DC Bus 211 Ground; Revision 7

BwAR 2-22-D6; 125V DC Bus 212 Ground; Revision 7

BwHP 4006-059; DC Bus Ground Location Using the Groundbuster Ground Locating
Equipment; Revision 1

BwHS 4002-136; Battery Impedance Test for Lead Acid Batteries in Stationary
Applications; Revision 2

BwHS TRM 3.8.c.4; 125 Volt ESF Battery Bank and Rack Surveillance; Revision 0

BwOP DC-15; DC Ground Isolation; Revision 1E1

1BwOS DC-1a; AAR *125V DC ESF Bus Ground; Revision 4

2BwOS DC-1a; AAR *124V DC ESF Bus Ground; Revision 4

2BwOS DC-1a; AAR *Action Chart 125V DC ESF Bus Ground; Revision 4

1BwOSR 3.8.6.1-2; Unit One 125V DC ESF Battery Bank and Charger 112 Operability
Weekly Surveillance; Revision 1

1BwOSR 3.8.4.5-2; 112 to 212 125V DC Crosstie; September 24, 2001

1BwVSR 3.8.6.6-111; Unit One 125 Volt ESF Battery Bank 111 Modified Performance
Test; Revision 0

CR A2000-00669; Battery Charger 112 Trouble Annunciator; February 12, 2000

CR A2000-00680; Problems During Troubleshooting of 125V DC Battery Charger
(Bus 112); February 12, 2000

CR A2000-00709; Potential Overtightening of Fasteners During Reterm of 1DC04E;
February 15, 2000

CR A2000-01912; 112 Battery 100V DC Negative Ground During Rain; April 16, 2000

CR A2000-02738; DC Battery 111Max Corrected Specific Gravity Deviation >
Administrative Limit; June 30, 2000

CR A2000-03445; Wrong Ground Detectors Installed; August 29, 2000


                                     19
CR A2000-04650; Incorrect Assumption Used in 125V DC Battery Sizing Calculation;
December 19, 2000

CR A2001-00551; Battery Charger 223 AC Input Breaker Tripped During Battery
Recharge

CR A2001-01444; AFW System Exceeded One-Half of the NEI/NRC Green Band Goal;
April 7, 2001

CR A2001-01897; Inadvertent Opening of AC Power Breaker CB-1 on Battery
Charger 211 - Unplanned LCOAR Entry; January 25, 2001

CR Pre-Screening 131318; Enhancement CR for Rework Reduction MA-AA-716-003;
November 12, 2002 (NRC Identified)

CR 00072371; DC Bus 212 Fluctuating Ground As High As 125V Pos; August 15, 2001

CR 00072507; DC Bus 112 Reoccurring Ground, Weather Related; August 18, 2001

CR 00075743; Fuses in 250V DC System Have Inadequate DC Voltage Rating;
September 17, 2001

CR 00089360; DC Ground on Bus 212 Requiring 2BWOs DC-1a Entry; January 7, 2002

CR 00091072; Part Concern on Transformer for 0DC08J; January 16, 2002

CR 00091825; DC Bus 212 Has a +62V DC Ground; January 23, 2002

CR 00092044; +70V DC Ground on DC Bus 212; January 24, 2002

CR 00104163; Prior Inoperability of Unit 1 and Unit 2 Pressurizer PORVs; April 16, 2002

CR 00105220; Discrepancy With Fuse Obtained From Stores; April 24, 2002

CR 00113947; Braidwood Station Degraded Mitigating Systems Cornerstone Root
Cause Report; July 26, 2002

CR 00112122; Positive 130 Volt Ground Indicated on DC Bus 111/113; June 14, 2002

CR 00115279; Equipment Reliability FASA Identifies Several Deficiencies; July 11, 2002

CR 00116575; DC Battery 223 Failed Acceptance Criteria 2BwOS DC-Q3; July 20, 2002

CR 00118891; Battery 211 Terminal Corrosion; August 10, 2002

CR 00119097; Loss of FME Integrity for 111, 112, 211, and 212 EST Batteries;
August 13, 2002

CR 00120793; DC Bus 212 Ground (+125V DC) Tied to 2B DG; August 27, 2002

                                      20
CR 00121683; Trend Code B4: 2ER-DC09E Indication and Alarm Found OOT;
July 10, 2002

CR 00133091; Potential Vulnerability–CRs During Work Package Closeout;
November 25, 2002 (NRC Identified)

CR 00133146; Enhancement–Due Dates and Nuclear Safety Impact Review;
November 25, 2002 (NRC Identified)

CR 133412; Potential Vulnerability in BwHS TRM 3.8.4.c Battery Surveillance;
November 22, 2002 (NRC Identified)

CR 134235; Potential vulnerabilities--Degraded Cornerstone Inspection;
December 4, 2002

Engineering Change Request (ECR) 0000042966; 125V ESF Battery Reduced Cell
Capacity Determination

ECR 0000081103; 125 V ESF Battery Reduced Cell Capacity Determination; Actioned
June 29, 2001

ECR 0000081112; 125V DC Crosstie Cables - Add Another Set of 350MCM Cables;
Canceled December 6, 2000

ECR 0000084162; Replace Ground Detector, Esterline Angus Model A601C Obsolete;
Canceled April 18, 2001

ECR 0000331612; 125V ESF Battery Reduced Cell Capacity Determination; Closed
December 4, 2001

ECR 0000337599; Temporarily Defeat the 125V DC Bus 111 Ground Alarm in the Main
Control Room; July 2, 2002

ER 00-001, PIF A2000-00669; Supporting Operability Documentation 1B 125V DC
Battery Charger 112; February 14, 2000

ER-AA-10; Equipment Reliability Process Description; Revision 1

ER-AA-2001; Material Condition Improvement Process; Revision 2

ER-AA-2002; System Health Indicator Program; Revision 1

ER-AA-2002; System Performance Monitoring and Analysis; Revision 2

IP 95002; Inspection for One Degraded Cornerstone or Any Three White Inputs in a
Strategic Area

IP 71111.12; Maintenance Effectiveness


                                      21
IP 71111.15; Operability Evaluations

IP 71111.16; Operator Workarounds

IP 71111.17; Permanent Plant Modifications

IP 71111.19; Post Maintenance Testing

IP 71111.21; Safety System Design and Performance Capability

IP 71111.22; Surveillance Testing

IP 71111.23; Temporary Plant Modifications

IP 71151; Performance Indicator Verification

IP 71152; Identification and Resolution of Problems

LS-AA-125; Corrective Action Program (CAP) Procedure; Revision 4

LS-AA-125-1005; Coding and Trending Manual; Revision 3

LS-AA-125-1006; CAP Process Expectations Manual; Revision 2

MA-AA-716-011; Work Execution & Close Out; Revision 0

MA-AA-716-013; Rework Reduction; Revision 0

MA-AA-716-232; Proactive Maintenance; Revision 2

NOA-BW-01-3Q; Nuclear Oversight Continuous Assessment Report Braidwood
Generating Station; July - September 2002

WC-AA-101-1001; Work Screening and Processing; Revision 1

Work Order (WO) 99238186 01; 1dc06e Isolate Ground Bus 112; November 18, 2002

WO 99269023 01; Ground Detector Indicator Always Shows 5 Volts; June 27, 2001

WO 00370371 01; Detector Locked Up At +125V Ground Detector, DC Bus 111;
July 11, 2002

WO 00430370 01; 125V DC Bus 111 Ground; April 12, 2002

WO 00447528 01; Rescale Ground Detector Setpoint; June 21, 2002

WO 00464003 01; Isolate/Repair Ground on 1MS101A; July 17, 2002

WO 99201097; Valve Will Not Close; June 25, 2001

                                       22
WO 00508150 01; Contingency W/O For Ground Busting 125V DC Bus 212;
November 19, 2002

WR 980008919 01; 125V ESF Distribution Panel Bus 112 Assembly 1DC06E Bus 112
Troubleshoot Grounds; February 13, 2002

WR 980070649 01; 125V DC ESF Distribution Center Bus Assembly 2DC06E Bus 212
Troubleshoot Grounds; November 12, 2002

WR 990068268 01; Contingency Package for Repairs at Battery Charger 112;
February 13, 2000

WR 990252122 01; 1B Auxiliary Feedwater Pump Battery Cell #18 Cap Keeps Opening;
June 14, 2001

WR 00031205; 212 Battery Ground Detector Detecting a Small Ground; January 8,
2002 (Cancel)

WR 00033335; Investigate +62V DC Ground on DC Bus 212; January 23, 2002

WR 00033539; Investigate +70V DC Ground on Bus 212; January 24, 2002

WR 00051253; Cell #21 Right-Most Positive Terminal Has Crystals; May 25, 2002

WR 00053308; Isolate Ground on DC Bus 111; June 13, 2002

Maintenance Rule Expert Panel Scoping Determination; DC System; as of
November 22, 2002

Maintenance Rule Data Request; DC Power Storage and Distribution System -
Unavailability + Reliability Graphs; November 1, 2002

Maintenance Rule - Performance Criteria; DC System; as of November 22, 2002

Maintenance Rule - Evaluation History; MR System DC; November 11, 2000 to
November 18, 2002

Braidwood Nuclear Power Plant System Monitoring Plan; Battery and DC Distribution
(DC); November 1, 2002

Braidwood Operations Narrative Logs; Unit 1; November 1, 1999 through
November 19, 2002

Braidwood Operations Narrative Logs; Unit 2; November 1, 1999 through
November 19, 2002

Braidwood Station Equipment Reliability Focus Area Self Assessment; May 29 through
July 8, 2002

SHIP Semi-Annual Report; September 2002


                                     23
                      LIST OF ABBREVIATIONS USED


ACE    Apparent Cause Evaluation
AFW    Auxiliary Feedwater System
ATI    Action Tracking Item
CAP    Corrective Actions Program
CAPR   Corrective Actions to Prevent Recurrence
CR     Condition Report
ECR    Engineering Change Request
ESF    Engineered Safety Feature
IP     Inspection Procedure
LER    Licensee Event Report
NEI    Nuclear Energy Institute
NRC    U.S. Nuclear Regulatory Commission
PI&R   Problem Identification & Resolution
PORV   Power Operated Relief Valves
SHIP   System Health Indicator Program
WO     Work Order
WR     Work Request




                                     24